CHAPTER 3 THE ROLE OF OTHER FUELS IN THE ENERGY SECTOR

Not surprisingly the economic viability of most wood based energy systems is currently determined by the relationship of the cost of this system to the cost of an alternative (e.g., oil, gas, coal) fossil fuel-based systems. Figure 1 would also suggest that this relationship is one that is likely to continue into the future too.

In some specific cases however, the economics of wood energy systems are determined not by reference to the cost of an alternative fossil fuel based system but by reference to the cost of disposing of material that would otherwise have to be regarded as wastes. There are also cases where the reference technology is, rather than a fossil fuel based one, some other renewable energy technology. Where appropriate, the question of the economics of wood energy compared to the economics of other renewable energy sources (e.g., wind, hydro, photovoltaics, solar, and geothermal) will be addressed. However, the major focus of the analysis is the relative costs of biofuels compared to fossil fuels for transportation, space heating and electricity.

3.1 THE ROLE OF FOSSIL FUELS

As Figure 1 clearly reveals, fossil fuels are currently the major world source of primary energy supply. Figure 1 also suggest that while the next 20 years are likely to see a switch in the relative importance of coal (currently number two) and gas (currently number three), as a group, these three fuels are if anything likely to increase their dominance of world primary energy supply. Thus costs of biofuels and the determination of whether they are ‘economic’ or not are likely to continue to be decided by reference to the cost of energy from these three fossil fuels.

To date a number of studies have shown that the cost of energy from biofuels is generally more expensive than the present cost of energy from non-renewable fossil fuels (e.g., NOVEM, 1992; OECD/IEA, 1994; EC, 1994). This conclusion is one that applies to older studies but also to newer studies too. Given past real world oil price behavior, as evidenced by Figure 2, it is not surprising that this conclusion has been reached consistently by many different studies over the last 30 years. However, one obvious difference between bio-based and fossil fuels concerns the question of renewability. At the most basic level most biofuels are renewable while most fossil fuels are not – meaning that once the world’s stock of these fuels have been used that will be the end of these products.

Figure 2: Real Crude Oil Prices (1996 dollars), 1869-1997

Source: www.wtrg.com/oil_graphs/crudeoilprice1869c.gif

Hotelling (1931) was the first to carry out the first serious examination of the economics of non-renewable resources. One of the major predictions of Hotelling’s analysis is that over time and in order to ensure optimal depletion of these resources, real prices for exhaustible resources such as oil, natural gas and coal must increase in a steady and predictable manner. Initially some increase may be due to the exhaustion of cheaper reserves that are part of the stock supplying current demand. However, even where the marginal cost of supply, the same for all possible sources of supply, the Hotelling model predicts that real prices of exhaustible resources will steadily increase. Specifically, under the rather ‘heroic’ assumptions of fixed technology and full knowledge of the full stock of these exhaustible resources, achievement of economic equilibrium requires that their real price increase at the real rate of interest.

The basic analysis ignores inflation, assumes resource owners of resources such as an oil field are able to instantaneously extract oil reserves, and doesn’t address the price effects of any excess supply of oil caused by a number of owners attempting to extract their oil assets at the same time. Nevertheless, it provides some rationale as to why real prices for exhaustible resources might be expected to increase exponentially at something like the general interest rate.

Perhaps not quite so obvious is the fact that Hotelling’s result applies only to that part of the price of the non-renewable resource that applies to the resource itself, and not to any costs associated with getting that resource to the consumer. That is to say, it applies to the value of the oil, coal or gas in the ground, not the price of the oil or other fossil fuel at the point of consumption. That price will include the costs of extraction and delivery as well as the intrinsic value of the oil itself.

In the real world though outcomes are seldom quite as so clear-cut as in the simplified world of the model. Technology is not fixed and knowledge of areas that will be affected by technological change (and the timing and impact of these changes), are not known with any degree of precision. Likewise, the actual stock of most non-renewable resources, particularly the stock of a one such as oil or natural gas, is generally not known with precision but rather is inferred from surveys and from the success rate of exploration efforts. As technology and understanding of the world progresses, the inferred stock of such resources can change quite dramatically. For example, in the last 100 years there have been numerous predictions about how the world’s supply of oil would soon be exhausted. Despite these predictions, recovered volumes have continue to increase, oil’s share of the world’s primary energy supply has grown dramatically, and the real price of the product, as Figure 2 shows, is today little different from the price one hundred years ago.

Still, it is not past oil prices and past estimates of future oil supply, which are relevant to the future of biofuels. The economic basis for the production of these must, in the next 10 to 20 years, rest to a large degree on the question of whether the price of fossil fuels, and in particular the price of oil and gas, will increase sufficiently to change the economic conclusions of most of the larger studies already mentioned. If demand for an exhaustible fuel such as oil continues at current levels then eventually its price must begin to rise. At some point the price should rise sufficiently that it reaches that of an alternative ‘back-stop’ fuel, a fuel whose supply is not constrained in the way of a non-renewable fuel. At this point substitution will begin to occur. Should demand for the non-renewable fuel be increasing with time rather than simply being constant (owing to such things as population growth, changing expectations, rising wealth etc), this will only serve to bring forward the point in time when price increases result in substitution.

This raises the possible that eventually the price of fossil fuels such as oil may exceed the price of renewable energy sources. Thus, major questions concerning the economic viability of biofuels (which as a general rule and without some form of assistance are clearly not currently cost competitive with fossil fuel equivalents) are:

a) What is the likelihood that biomass will be the resource for the production of a ‘back-stop’ fuel?

b) What is the magnitude of the price increase required to produce indifference between using biofuels and fossil fuels?,

c) What period of time may be required to produce price increases of required magnitude to produce this indifference?

Obviously it is never possible to be absolutely certain about what will eventually turn out to be a ‘back-stop’ technology. However, in general, the wider the gulf between the cost of the current technology/fuel and its alternative as a potential back stop, the greater the scope for something else to intervene between the two. So a useful starting point in any evaluation of biomass’s potential to provide the backstop energy resource is an evaluation of the current and projected future cost of oil.

3.1.1 THE COSTS OF FOSSIL FUELS

At present the total cost of finding and producing oil ranges from around US$3 to US$12 per barrel (Anon, 2000). Although it is difficult to determine an average world production cost for oil, it appears that the average cost for much of the world’s present supply (including amortization of capital and exploration outlays) is less than US$6 per barrel (Anon, 2000a). That cost, in real terms, would appear to be less than that reported two decades ago (Isaak & Hoffman, 1983) and perhaps serves to highlight the differences between the real world and that applying in a model.

Production costs for incremental oil supplies are as difficult to determine as the average cost of supply. However, many countries are (as a matter of policy) producing oil at less than their physical capacity and as a result the production costs of short-term incremental supplies may not be much different from present production costs. Longer term, the cost is going to depend on a number of things, including how much new oil is discovered. The fact that at present oil is being produced from high cost locations (e.g., the North Sea), while other cheaper resources remain less than fully utilized, is a result of political rather than economic or resource factors; constrained supply makes it possible to produce from fields that would not be exploited for many years under “free market” conditions.

Figure 3: Current World Oil Production
Cost

Source: Anon, 2000

Although oil prices more than doubled in real terms between 1998 and 1999, that short-term development is not indicative of the longer-term price trend as projected by the International Energy Agency in its most recent outlook (IEA, 2000). In this, short-term oil prices are expected to continue to remain at levels similar to those applyed during the latter months of 1999 and throughout all of 2000. However, it should be noted that the IEA reference case assumes OPEC production cutbacks will be relaxed and that non-OPEC production will, as a result of the higher prices, increase. The main result of this is that over the medium term, prices are expected to fall back slightly from the 2000 level. After that, prices increase, but only slowly, over the longer term.

In the IEA scenario, world oil demand is projected to grow from 76 million barrels per day (2000) to almost 115 million barrels per day by 2020. OPEC producers are expected to be the major beneficiaries of increased production requirements. However, non-OPEC supply also remains competitive, with major increments to supply coming from offshore resources, especially those in the Caspian Basin and in the waters off the coast of West Africa.

Over the past 25 years, oil prices in real 1998 dollars (US) have ranged from US$12.10 to US$63.30 per barrel. The price behavior over this time period has been nothing like the smooth and exponentially rising price predicted by the Hotelling model. Nor does the IEA’s year 2000 outlook study suggest that the world has yet reached a stage where all reserves have been found or where projected growth in oil production is possible only with severe price escalation. Not that there is universal agreement with this particular conclusion. There are oil market analysts who find this viewpoint to be overly optimistic, and who believe that it is based on what they consider to be a significant overestimation of both proven reserves and those that will ultimately prove to be recoverable.

Although Figure 2 reveals that over the last 100 years there has not been any significant and sustained real increase in oil prices, it does show that there has been considerable price volatility. Regardless of views on whether the IEA has been overly optimistic or not it is unlikely that future prices will be any less volatile than past prices. As with the past, future volatility may well be associated with unforeseen political and economic circumstances (e.g., political tensions and/or wars). Some of these events could give rise to serious disruptions of normal oil production and trading patterns. However, although significant deviations from the IEA’s reference price trajectory are very possible, such deviations (provided the underlying assumptions are valid, for example in terms of total forecast supply) are unlikely to be sustained for long periods. High real prices not only deter consumption but also encourage the emergence of significant competition for the current supplier from marginal but potentially important sources of oil and non-oil energy supplies. Persistently low prices have the opposite effect.

Limits to long-term oil price escalation include not only substitution of fuels derived from biomass, but also substitution (at least in the short term) of oil by other fossil fuels such as natural gas, the utilization of marginal sources of conventional oil (which become reserves when prices rise), and the utilization of non-conventional sources of oil (e.g., shale tars) which are likely to become part of the reserves at still higher prices. Improved exploration and production technologies are also likely to have some ameliorating impact on prices when such additional oil resources become part of the reserve base.

The major highlights of the IEA 2000 projection for the world oil market are as follows:

• the reference case price projection has an oil price increase of more than US$4 per barrel in the period 1999 to 2000, which is followed by a decline of slightly less than US$3 per barrel in 2001 to a price of some US$21/barrel;

• stable prices are assumed throughout the rest of the decade with prices only beginning to increase, by about 3 percent per annum, after 2010. Prices reach some US$28 per barrel (current dollar terms) by 2020;

• deepwater exploration and development initiatives are assumed to be sustained worldwide, with fields offshore from West Africa emerging as a major future source of oil production;

• technology and resource availability are assumed to sustain large increments in oil production capability at the reference case prices;

• economic development in Asia is seen as a major factor in the long-term growth in oil markets;

• natural-gas prices, for most areas of the world, are projected to increase in line with oil prices from 2010 onwards, although US natural gas prices are forecast to start increasing some five years earlier (2005) in response to supply-side pressures.

As a result of these various assumptions OPEC’s share of the world oil supply is projected to increase significantly over the period to 2020. However, in the reference scenario, competition among energy producers is expected to be sufficiently robust to forestall any efforts aimed at achieving a significant escalation of real oil prices. Competitive forces are seen as not only applying between OPEC and non-OPEC sources of supply, but also between various OPEC members, and between oil producers and producers of other sources of energy (particularly natural gas). Still, despite the generally optimistic tone for oil and other fossil fuels in the IEA outlook projection, there are significant uncertainties associated with the IEA 2000 reference case - uncertainties that are likely to have implications for ongoing investment in biofuels.

The latest IEA world consumption projections for petroleum over the next 5 years are slightly lower than in its 1999 study (about 1 percent less in 2005). This reduction is due to the higher oil prices expected in the near term, as well as the lingering effects of the economic slowdown in Asia, Central and South America, and Russia. In the latest scenario, oil provides a larger share of world energy consumption than any other energy source. Petroleum is used heavily in the transportation sector and is also used to provide heat and power as well as industrial feedstocks. World oil consumption is projected to increase by a total of 39.8 million barrels per day (an average rate of 1.9 percent per year), from 73 million barrels per day in 1997 to 114.8 million barrels per day in 2020. Between 1970 and 1997, oil use rose by a total of 26.2 million barrels per day, an average annual increase of 1.7 percent. Oil’s share of the energy market (currently 39 percent) is expected to decline only slightly over the forecast period. Industrialized countries, currently the largest consumers of petroleum, are expected to remain the largest users through to 2020. Oil consumption in the industrialized countries is projected to rise from 43.1 million barrels per day in 1997 to 54.5 million barrels per day in 2020. However, developing countries are expected to make the largest contribution to the increment in oil demand, an increase of 24.7 million barrels per day between 1997 and 2020. This represents some 62 percent of the growth in worldwide petroleum consumption over the period. Petroleum consumption in developing countries as of 1997 was 56 percent of the total consumption in industrialized countries, but in the IEA scenario is projected to reach 90 percent of that in the industrialized countries by 2020.

In summary, the world of the IEA outlook, and the world in which bioenergy projects and in particular wood energy projects and systems are most likely to be evaluated, is one where there are more than adequate supplies of fossil fuels to meet projected needs. It is a world where real oil prices are expected to rise by about a third over the next 20 years (from US$21/barrel to something like US$28 per barrel by 2020) and where the importance of natural gas as an energy source is expected to exceed coal by about 2015.

At present the world oil price of US$29 to US$30 per barrel is somewhat above the IEA’s 2001 projection of US$21/barrel. The current oil price is also consistent with a tax exclusive price of US$0.29 to US$0.35/litre for gasoline; US$0.30 to US$0.36/litre for automotive diesel; and US$0.29 to $ US$0.35/litre for domestic heating oil (IEA 2000a). For biofuels to be competitive with oil-based fuels now, they would need to be produced at similar prices to these. However, one should bear in mind that wood energy use is more localized, and depending on specific circumstances they can be competitive with fossil fuels at current prices.

Going beyond the immediate and into the medium/longer term, the IEA’s World Energy Outlook is recognized as the authoritative source of medium-term energy projections. The IEA reference scenario forms the basis for much analysis of national and international energy policy. To gain general acceptance that on purely economic or resource cost grounds, biofuels have the potential of substituting oil based fuels during the period covered by the IEA’s scenario. There is a high probability of biofuels becoming less costly to produce, than oil based fuels at some point of time in this scenario. In this case, as the reference scenario projects a real oil price over the next 20 years which in fact is never higher than the current oil price, means showing that there is some expectation of producing biofuels for less than US$0.30 to US$0.36 per oil based liter equivalent or at something like US$9 to $ US11/GJ. This is the price range that forms the basis for much of the following analysis and discussion, which begins with an examination of thermochemical technologies.

3.2 THE ROLE OF THERMOCHEMICAL TECHNOLOGIES

Thermochemical processing of biomass and wastes offers a number of means of energy production and, where applicable, a potentially attractive method of waste disposal. In addition to simply providing heat biomass, wastes can be converted into a mixture of gases, liquids and carbon char (see Figure 4). The proportions of the various products are dependent upon the feedstock, temperature and pressure of the reaction, the time spent in the reaction zone, and the heating rate.

Figure 4: Thermochemical Conversion Processes and Primary Products

Source: Author

Large industrial scale furnaces and boilers have been developed for burning bark, wood, woodwastes, black liquor from pulping operations, food industry wastes and municipal solid wastes (MSW). The high moisture content and variable composition of much biomass makes it difficult to achieve the same cost-efficiencies as fossil fuel furnaces in smaller units, but larger units can be very efficient, nearly matching the performance of fossil fuel furnaces.

With combustion of biomass and waste, an established technology, the major areas of current research focus appear to be pyrolysis and gasification. However, combustion technologies warrant mention simply because of their dominant role among technologies currently in use.

3.2.1 COMBUSTION

At present the principal biomass conversion technology remains direct combustion, (Jackson & Löfsedt, 1998). Biomass resources of various types are burnt in stoves, furnaces and boilers either to provide energy directly to end-users, or else to raise steam for electricity generation in steam turbines. Moreover, despite likely increases in the importance of other thermochemical and biochemical conversion processes, direct combustion should remain the principal biomass conversion technology for some considerable time yet.

At the most general level there is considerable potential to enhance both the status and efficiency of combustion systems. Improved status and efficiency for combustion is also likely to result in a general increase in the status of biomass as a fuel. At present in many instances biomass is generally (and wrongly) regarded as a low status fuel (Hall & House, 1994). There is a wide gulf between the energy efficiency of most traditional combustion systems, which typically end up utilizing only some 5 to 15 percent of the energy in the biomass, and efficiencies currently achieved in many bioenergy industrial situations. (Johansson et al., 1993). The latter can convert between 80 and 90 percent of the energy in the fuel into useful power and heat (Kellett, 1999).

The gulf between household and industrial energy efficiencies provides much of the rationale for a number of combustion research projects. Projects range from ones with goals of designing, producing and gaining acceptance of stoves which are significantly more energy efficient than those currently in general use through to ones seeking to demonstrate and increase knowledge of the conditions required for biomass fueled heat and power (CHP) systems to be economically and financially competitive with fossil fueled power systems.

Use of modern combustion systems has been widely advocated in Scandinavia, (Jackson & Löfsedt, 1998), who also claim bioenergy production in the five Nordic countries (Iceland, Norway, Sweden, Finland and Denmark) is currently equivalent to the energy contained in 15 million ton of oil. (The current exploitable bioenergy potential of the five countries is estimated to be double this figure (ibid.)). Sweden has almost half the group’s exploitable bioenergy potential, and biomass already accounts for 15 to 18 percent of that country’s primary energy consumption8

Swedish policy-makers first became interested in promoting the use of biomass energy following the 1979 oil embargo, a time when Sweden was dependent on oil for more than 70 percent of its energy needs, (Jackson & Löfsedt, 1998). In the mid-1980s concern to reduce oil consumption subsided but in its place policy-makers began to advocate use of biomass-fired electricity as a way of alleviating the difficulties of a proposed phase-out of nuclear power. Jackson & Löfsedt, (1998) citing Holm (1995) state that over a twenty-year period from the mid-1970s to the mid-1990s the Swedish government invested more than 2 billion Swedish kroner (almost US$275 million) in developing biomass. Subsidies covering up to 25 percent of the capital cost of plant resulted in a doubling of the contribution from biomass between 1970 and 1995.

Not all commentators see capital subsidies as the sole or even the most important factor in explaining the growth in the Swedish bioenergy capacity. Roos et al., (1998) attributes increasing Swedish consumption of biofuels by both industry and in district heating schemes to widespread availability of low cost woodfuels from logging and wood processing. In addition and instead of capital subsidies these authors also regard increased energy and environmental taxes on fossil fuels which “have improved the competitiveness of all biofuels” as being significant.

The precise balance between direct subsidies for projects, taxes on alternatives and/or the availability of a low cost biomass supply in tipping the financial balance in favor of biofuels obviously varies between projects, from country to country and between regions within any individual country. However, one feature common to all cases where there has been significant growth in use of modern biomass based combustion systems in the last 10 to 20 years has been the significant encouragement of this growth via national policy measures. In Europe, Sweden obviously provides one example of this. Austria also provides a similar example of encouragement, the contribution of biomass to Austrian primary energy supply having increased from near zero at the start of the 1980s to around 12.6 percent today. Growth in Austria’s biomass energy in fact represents a 10 percent point increase in little more than a decade. More than 10,000 woodchip-fired combined heat and power (CHP)/district heating schemes have been installed in the country since 1979, and bioenergy accounts for some 12.6 percent of the country’s primary energy demand9. Heating plants, installed in Austria in the last 20 years, range in size from a few hundred kW up to 8 MW (Roos et al., 1998).

Generous subsidies are one significant force behind the growth of the Austrian bioenergy program - with plants run by farmer cooperatives being the most favored. Roos et al., (1998) claim that if contributions from local and federal government are combined with those from various EU structural funds subsidies of up to 50 percent of total investment costs are possible for farmer cooperatives prepared to invest in biofuel powered heating schemes. (Support for other operators/investors is more usually in the range of 10 to 30 percent of capital cost (Roos et al, 1998)). Roos et al., (1998) also report that the fuel used by the Austrian district heating plants is predominantly wastes from forest industry or wood from thinning - this latter though is claimed to be a relatively expensive fuel, a point that would be in accord with results of studies looking at the economics of commercial plantation forestry. However, positive externalities can be associated with the use of this material. In particular a market for thinning can encourage forest owners to thin their forests producing an improvement in the overall quality of forest stands.

There are a number of other European examples too that may be cited. In the UK, a variety of different kinds of biomass projects – ranging from incineration of residues to gasification of energy crops – have been set up under that country’s Non-Fossil Fuel Obligation (NFFO) (Jackson & Löfsedt, 1998) while in Denmark at least some of the growth in Danish use of biofuels is attributable to a 1986 agreement between government and utilities which required the latter to convert 6 percent of their coal consumption to biofuels before the year 2000 (Caddet, 1998).

In parts of the USA, notably the northeast and in particular in the state of Maine, there has been significant growth in biomass based electricity production, most notably during the 1980s and early 1990s. Biomass-fired electricity generation in the USA has increased from 250 MW to 9,000 MW. As with the Swedish and Austrian stories much of the development and growth in this form of bioenergy production in the US is attributable to a number of quite site/region specific conditions that have favored this growth, and to the impact of public policy. In the US the Public Utility Regulatory Policies Act (PURPA) legislation of 1978 guaranteed to small producers that utilities would purchase their surplus electricity at a price base on the utilities’ avoided cost of production. This created a window of opportunity for alternative energy forms (Anon, 1992). However, with contracts between independent power producers and utilities controlled by this legislation due to terminate in the next few years the biomass power industry in states such as Maine may well have to find new ways to meet the challenge of changing market conditions (Roos et al, 1998).

Quoted costs of biomass energy vary widely, and are heavily dependent on a number of factors, including the type, availability and quality of the feedstock being used and the conversion technology employed in the conversion. Some biomass feedstocks – typically those that are drawn from industrial wastes and residues for example – may in fact have a "negative cost" in some situations simply because of the avoided costs of alternative disposal. This situation where it applies can, and does, give rise to highly competitive energy generation options. However, the economics of bioenergy systems based on this sort of material are obviously both highly site and situation specific.

In countries such as Sweden, Finland and Austria with extensive woodfuels contribution to the energy supply the market for woodfuels is relatively well developed. Costs – claimed by Jackson & Löfsedt, (1998) to in the region of UK£2-3 per gigajoule (GJ) [US$2.8 to US$4.20/GJ] – are claimed to be competitive with conventional fuels which is probably true for small scale operations given that bulk coal trades internationally at around US$1.30/GJ (Anon, 2000). In the countries mentioned most woodfuel is sourced from conventional forest crops and is recovered as a by-product of the main crop. There is very little in the way of purpose grown energy crops, and certainly little in the way of purpose grown woodfuels crops. For the countries concerned woodfuel is a low value product, particularly when compared to products such as lumber, veneer, and even pulpwood with the financial contribution made by this product to the commercial value of the stand being minimal, (Richardson, 2001).

As the constraints implied by both the type of energy forestry typically employed and the market value of the product costs of harvesting operations need to be very carefully controlled, cost of producing the fuelwood can vary significantly depending on the elements present or absent from each harvest system. Typical though, and reflecting the fact that fuelwood is a by-product of the main reason for growing the tree crop, analyses do not include a cost of growing the biomass used by the system. Costs of fuelwood although they may be described as production costs are really procurement costs and simply reflect costs harvesting and collection of the biomass used by the system. Typically costs included are those relating to cutting, stacking, chipping, forwarding to roadside, and truck transport to point of use plus a charge for administration and overheads (Richardson, 2001).

When wastes and residues form the basis of the bioenergy supply the location and scale of demand are also likely to impact significantly on the cost of procurement. Richardson (2001) demonstrates this with an example from Finland showing the average cost of supplying 200,000 m3 of logging residues per annum to a biomass power plant varying by almost 50 percent (from US$8.80 to US$12.90 per m3) depending on the area of the country the residues are drawn from. The example also shows that for any one region doubling the demand from 200,000 m3 to 400,000 m3 per annum also results in a significant increase in average cost per unit supplied – in the case of the example anywhere from 15 percent up.

3.2.2 PYROLYSIS

Fast pyrolysis is one of the most recent biomass technologies used to convert biomass feedstocks into higher value products to emerge. Any form of biomass can be used (over 100 different biomass types have been tested in laboratories around the world), but cellulose gives the highest yields at around 85-90 percent wt on dry feed.

This is a high temperature process in which biomass is rapidly heated in the complete absence of an oxidizing agent, or with such a limited supply of such an agent that gasification does not occur to any appreciable extent. Heat is usually added indirectly and gas, liquid and char are produced. The relative proportions of each depend very much on the key parameters of temperature and reaction time.

In a fast/flash pyrolysis unit, the process is controlled in a way that gives high yields of liquids as compared to the high charcoal yields of more traditional pyrolysis units. The essential features of flash/fast pyrolysis are:

• very high heating and heat transfer rates. This usually require a finely ground feedstock;

• a well controlled pyrolysis reaction temperature of around 500°C in the vapor phase with short vapor resident times (typically of the order of no more than 2 seconds); and

• rapid cooling of the pyrolysis vapors to give the bio-oil products.

This oil is referred to by a number of different names in the literature, including pyrolysis oil, bio-crude-oil, bio-oil, bio-fuel oil, pyroligneous tar or acid, wood liquids, wood oil, liquid smoke, wood distillates and liquid wood. It is typically a dark, free flowing liquid with a distinctive acrid smoky smell (Bridgewater, 1999). Table 2 summarizes the main characteristics of wood-derived pyrolysis oils.

• Heating value is about 40% that of fuel oil or diesel on a weight basis and 60% on a volume basis.

• Does not mix with hydrocarbon fuels.

• Not as stable as fossil fuels. Source: Bridgewater, 1999

Bio-oils are complex mixtures of the degradation products of ligno-cellulose. They are quite different to the more familiar petroleum derived oils. The high oxygen content of these oils makes them hydrophilic rather than hydrophobic. In addition, they have a poor miscibility with hydrocarbon solvents (Radlein, 1997). The oils are maintained as a liquid because of the presence of water, typically in the range of 15 to 25 percent by weight, and the molecular components of the oil originates from the lignin as well as from the cellulosic components of the feedstock. The various organic chemical components of the oil vary in size from simple low molecular weight compounds to large fragments with molecular weights of 1000 or more (Radlein, ibid.).

Besides hydroxyl and methoxyl groups, the oxygen present in the oils is also associated with functional carbonyl and carboxyl groups. This renders the oils reactive, thermally unstable, and susceptible to aging if stored. As a result of this reactivity and thermal instability, conventional separation techniques such as distillation are not applicable to these oils.

As a fuel, bio-oil can substitute directly for fuel oil or diesel in many static applications, such as boilers, furnaces, engines and turbines for electricity generation. In addition to its use as a fuel there are a range of chemicals that can either be extracted or synthesized from bio-oils. These range from food flavorings to resins, agri-chemicals, fertilizers and emission control agents (Radlein, 1997; Radlein, 1998).

A number of pyrolysis/liquefaction processes have been subject to techno-economic assessment as part of IEA’s international collaborative agreement on bioenergy. Beckman et al., (1990) and McKeough et al., (1988) provide reviews of a number of processes in studies comparing the production costs of synthetic gasoline and fuel oil substitutes. Solantausta et al., (1994) examined a high-pressure conversion process of straw to fuel oil, based on a process researched at the University of Manchester in the 1980s (Bult, 1987) and production of a gasoline blending feedstock from the catalytic cracking of the vapors from the pyrolysis of woodchips. More recently Beckman & Radlein (1999) and Östman (1999) have looked at the relative economics of producing a slow release fertilizer from using bio-oils in a district heating scheme.

Most of these analyses, as well as assessments of the technology (e.g., Bridgwater and Evans, 1993), reveal significant economies of size (scale) in pyrolysis systems. However, the cost of the oil produced by any flash pyrolysis systems is dependent not only on the size of the unit but also on the cost of the feedstock to the unit. Radlein (1997), while acknowledging that most of the pyrolysis research effort at that time was targeted at fuel applications, states that such applications are “only potentially viable, i.e. without subsidy, for certain waste feedstocks”. Bridgwater (1999) summarizes the results of a number of detailed cost analyses for a range of plant sizes (covering plants with input processing capacities of between 8,000 and 160,000 oven dry tonnes per annum) and feedstock costs, both graphically and in the form of an equation. Figure 5 gives the reported cost of bio-oil with free feedstock.

Figure 5: Bio-Oil Production Cost Versus Capacity (Free Feedstock)

Source: Bridgewater, 1999

The exchange rate ruling at the time Figure 5 was prepared was 1ECU equivalent to US$1.15. At this exchange rate, the production costs for crude bio-oils (excluding feedstock costs) are of the order of US$4.60/GJ. With the calorific value of a barrel of crude oil (159 liters) ranging between 5.03 and 6.35GJ (Anon, 2000) the cost of producing bio-oil with the same calorific content as that in a barrel of crude oil is of the order of US$23 to US$29. However, this is the cost with free feedstock. In addition to the processing cost there is also likely to be a cost associated with the feedstock used by the process – if only the cost associated with the collection of up to 160,000 OD tonnes per annum at a single site.

The Bridgwater analysis considers two possible feedstock costs: 50 ECU/t and 100 ECU/t. These are equivalent to feedstock costs for wood of the order of (respectively) US$23/m3 and US$46/m3. Inclusion of this feedstock cost has the affect of adding some US$4.60/GJ (feedstock at 50 ECU/t) to US$9.20/GJ (feedstock 100 ECU/t) to the base (zero feedstock) cost of bio-oil. With processing costs alone resulting in a bio-oil cost that in dollars per GJ of energy is similar to that currently applied for oil, inclusion of a positive feedstock cost of the magnitude considered results in bio-oil costing, on an energy basis, some two to three times the current cost of crude oil.

Feedstock cost is thus a critical issue in terms of the total resource cost of bio-oils. While cases where costs are lower than the range indicated above may be found, these are specific instances and usually involve utilization of material which would otherwise have be disposed of at a cost. Australasian, North American, and European work on the cost of producing significant volumes of purpose-grown fiber for fuel use have, typically, resulted in feedstock costs in the US$25 to US$40/m3 range (e.g., Rawlins et al, 1982; Graham et al, 1995; Samson & Girouard, 1998; Turhollow, 2000; Sims et al, 1991; Mitchell et al, 1995). However, one can find other, lower cost estimates. For example Carpentieri et al. (1998)estimated that 13 EJ/yr of biomass could be delivered from plantations in northeast Brazil, at US$1.5/GJ (approximately US$12/m3). Girouard et al., (1996) give the costs for energy from switchgrass plantations as being some US$1.70 to US$2.33/GJ and the goal of US Department of Energy short rotation woody crops (SRWC) research is a 2010 delivered material cost of US$1.70 to US$2.35/GJ (Anon, 1992). (The US goal figures would translate to delivered biomass costs of the order of US$13 to (perhaps) US$20/m3).

Other sources of biomass include industrial residues (e.g. pulp and paper waste), forestry residues, and agricultural residues (e.g. straw). These sources can be very cheap or even free of cost, depending on the competing demands and ease of transport. Generally though costs of agricultural residues would appear to be higher in Europe than in the USA. Typically quoted costs are in a range US$4 - US$6/GJ for Europe, compared to US$2.5 - US$4/GJ in the USA. The opportunity cost of large volumes of residue material from conventional forest crops or processing is typically in a range of US$1.30 to US$3.20/GJ - US$25 to US$60 per OD tonne (Ford-Robertson et al, 1996; Li et al, 2000). Not surprisingly given these costs and the cost of other fossil fuels (e.g. coal at around US$1.30/GJ(Anon,2000)) the possibility of producing specialty chemicals is seen as currently offering more interesting immediate commercial opportunities for bio-oils than the production of fuels (Bridgwater, 1999). If fact chemical rather than fuel production is likely to be the major focus of R&D efforts, at least for the immediate future.

3.2.3 GASIFICATION

Gasification offers greater opportunities than pyrolysis, given the substantial technological development (particularly small scale) of the past decade.

Gasification is a pyrolytic technology that has been used since 1830 to produce biogas from organic matter (Jackson & Löfsedt 1998). An estimated one million gasifier-powered vehicles helping keep basic transport systems running when oil resources were scarce during the Second World War (ibid.). Interest in the technology waned in the post-war period, but was rekindled by the oil crises of the 1970s, and extensive demonstration programs were carried out in a number of countries. In Brazil, for example, small charcoal gasifiers were extensively installed in rural areas for electricity generation, or to provide gas for internal combustion engines (Luengo & Cencig, 1991). In principle, gasification offers the possibility of using high-efficiency power conversion cycles. However, Jackson & Löfsedt (1998) state that the economics of gasification are currently marginal, particularly for power generation.

Thermo-chemical gasification involves decomposition and devolatilization reactions that may be represented as:

CaHßO? + yO2 + zN2 + wH2O + dh ?

x1C + x2H2 + x3H2O + x4CO + x5CO2

+ x6CH4 + x7CµHp + x8O2 + x9N2

In this equation CaHßO? represents biomass, and y, z and w are molar numbers of oxidant. Air (oxygen, nitrogen, water vapor), oxygen, steam or a mixture of these may be used in this partial oxidation.

On the output side of the equation, x1, x2, x3, etc, are molar numbers of char, hydrogen, carbon monoxide, carbon dioxide, methane, higher hydrocarbons (tar vapors), traces of unreacted oxygen, and nitrogen produced by these reactions. In theory, zN2 should be equivalent to x9N2 (i.e., the nitrogen in the air remains inert). The heat requirements (dh) for the reaction to occur may be supplied either by in situ combustion of part of the biomass or heat applied from an external source. Note that by replacing air in the reaction with pure oxygen, all nitrogen is removed from the mass reaction equation.

Air gasification produces a low heating value (LHV) gas (4-7 MJ/Nm3), while oxygen gasification produces a medium heating value (MHV)gas (10-18 MJ/Nm3) – refer Figure 4. Although air gasification produces a low heating value, it is the more widely used gasification technology. It avoids the cost and hazard of oxygen production and usage, as well as the complexity and cost of multiple reactors. The product, consisting of char (carbon), H2, H2O, CO, CO2, CH4, and CµHp (with O2, and N2), is a relatively low energy density combustible gas which may be burned directly for space heating or drying, or which may be used in a boiler to produce steam and/or electricity or (after some cleaning to remove entrained char) in an internal combustion engine.

There are a variety of gasifier types, the main features and limitations of which are listed in Table 3.

Producer gas, formed by oxygen gasification, contains carbon monoxide, hydrogen, water vapor, carbon dioxide, tar vapors and ash particles, and about 70 to 80 percent of the energy present in the original biomass. This may be used in the same way as the gas from air gasification, or as the starting material for a petrochemicals industry based on the technologies typically applied to natural gas.

The precise specifications of the products of gasification vary according to the reactor configuration on the oxidant used. Although gasification should ideally achieve complete conversion of all tars, hydrocarbons and char into a gas, in reality all gasification technologies produce a gas contaminated to an extent by ash, char, tars, etc. The amount of these contaminants depends on the feedstock and reactor type, while the seriousness of any contamination depends on the use being made of the gasification product.

As with flash pyrolysis there are economies of size/scale in gasification plants (see Bridgwater & Evan 1993; Anon, 1979). Faaij (1997) and Graham et al (1995) outline some low cost biomass production and biomass wastes in which it would appear that commercial electricity production via a gasification system is already economic. However, such cases appear to be quite site-specific. Nevertheless, there are indications that in the longer term, biomass gasification systems may be widely capable of producing electricity at a cost that is competitive with that of electricity from other systems (Graham et al, 1995; Anon, 1992).

Table 3: Comparison of Gasifier Types

Mode of Contact

& Gas Quality

Features

Limitations

Downdraft of Co-current

Solid moves down, gas moves down

Very low tar levels

Moderate particulate levels

Simple, robust construction

Proven for certain fuels

High carbon conversion

Low ash carry over

Close specification on feed

Low specific capacity

Not for high moisture feeds

Poor turn down capability

Clinker formation on grate

Updraft of Counter-current

Solid moves down, gas moves up.

Very high tar levels

Moderate particulate levels

Simple robust construction

Good scale up potential

High thermal efficiency

High carbon conversion

High residence time of solids

Suitable for direct firing

• Low specific capacity

• Not for high moisture feeds

• Poor turn down capacity

• Clinker formation on grate

Fluid bed

•
Gas moves through a bubbling bed

• Inert solid stays in the
reactor

• Fair tar levels

• High particulate levels

Good temperature control

Good scale-up potential

In-bed catalysts possible

Increases particle size range

High specific capacity

High reaction rate

Good turn down capability

• Low feedstock inventory

• Carbon loss with ash

Circulating fluid
bed

• Gas moves through a bubbling bed

• Particles are
elutriated and recycled

• Low tar levels

• Very high
particulate levels

• Good temperature control

• Very good scale-up potential

• Increased particle size range

• High reaction rate

• High carbon conversion

• Relatively simple construction

• In-bed catalysts not possible

Entrained
flow

• Fine feed carried by high velocity gas

• No
inert solids

• Low tar levels

• Very high particulates
levels

• Very good scale-up potential

• High carbon conversion

• Costly feed preparation required

• Only practical above ~10t/h

• Slagging of ash

• Materials of construction

• Low feedstock inventory

Twin fluid
bed

• Pyrolysis occurs in the 1st reactor

• Char combustion in the 2nd reactor heats the bed material for
the first reactor

• High tar levels

• High particulate
levels

• MHV gas using air only

• In-bed catalysts possible

• Complex, costly design

• Only practical above ~5t/h

• Scale-up possible but complex

Source: Toft and Bridgwater, 1996

Liquid fuels (in particular methanol and petroleum) can also be produced from gasification products via processes that are currently employed on natural gas (Anon, 1979; Solantausta et al, 1994). The cost of manufacturing methanol from a large-scale wood gasification/methanol plant would, based on New Zealand work from the late 1970s (Anon, 1979), be currently of the order of US$18/GJ. While methanol could be used in its own right as a liquid transport fuel, it can also be converted catalytically into gasoline (Isaak & Hoffman, 1983). That would add US$18/GJ (or US$362/tonne) to the methanol cost, should it be required. This cost may be contrasted with the current cost of premium grade petrol (tax excluded) of some US35c/litre (IEA, 2000a), or equivalently US$7.7/GJ. Similarly, this may be contrasted with the international price for bulk methanol from natural gas, which currently ranges between US$200 and US$270 a tonne (www.methanex.co/methanol.currentprice.htm). That is, biomass methanol is at least a third more expensive than methanol from natural gas or, on a dollars/GJ of energy basis, more than twice as costly as petroleum derived gasoline.

Figure 6: Outputs from Gasification of Natural Gas

Source: www.methanex.co

3.3 THE ROLE OF BIOCHEMICAL PROCESSES

The main biochemical conversion process is fermentation: the breaking down of organic matter through the metabolic action of microbial organisms. Anaerobic fermentation is a simple, reliable, and versatile method of producing biogas from organic matter. There are approx. 7.6 million households in China with biogas digesters, that generate over 200 million m3 of biogas annually; and some 700,000 in India (Jackson & Löfsedt, 1998). While the original purpose of the Chinese digesters was to reduce disease among rural communities by stabilizing local sewage, their subsequent optimization for biogas production has been a substantial benefit in terms of that country’s rural energy provision (ibid.).

Ethanol fermentation is another well-known and relatively simple biomass conversion process in which microorganisms (usually yeasts) are used to convert carbohydrates into alcohol. The feedstocks and production processes for creating ethanol are diverse. Fermentation alcohol may be produced from grain, molasses, fruit, whey, cellulose, and numerous other sources. Synthetic alcohol may be derived from crude oil, gas or coal. Fermentation alcohol and synthetic alcohol are chemically identical.

On a global scale, synthetic feedstocks play a minor role in ethanol production while biomass plays the major role. Only seven per cent of overall output is accounted for by synthetic feedstocks. Roughly 60 per cent of world ethanol production is from sugar crops (mostly sugarcane), and the remainder mostly from corn.

Commercial ethanol contains about five per cent water, referred to as hydrous (water-containing) alcohol. Removing the last traces of water gives “anhydrous” or “absolute” alcohol. Ethanol is the alcohol of beverages, but it is also widely used as an industrial solvent and is the starting material for the preparation of many industrial organic chemicals. “Denatured” alcohol is unfit for human consumption, but is suitable for many other purposes. Denaturing is achieved by the addition of a small proportion of foreign materials that are not easily removed.

3.3.1 ETHANOL

Ethanol’s history as a fuel dates back to the early days of the automobile. However, cheap petrol (gasoline) quickly replaced ethanol as the fuel of choice, and it was not until the late 1970s (when the Brazilian government launched their “Proalcool” program) that fuel ethanol made a come back to the market place (Berg, 1999). Today, fuel ethanol accounts for roughly two thirds of world ethyl alcohol production, with Brazil and the United States being the two major producers (Berg, 1999). The Proalcool program is perhaps the best known ethanol fuel program, but there are also programs in a number of other countries - notably the US, Malawi, - and many others under consideration e.g. Argentina, Colombia, China, India, and Mexico.

The potential of ethanol as an alternative automobile fuel has not been fully recognized worldwide, despite being the most promising and realistic alternative to oil in the transportation sector in the short term. Current world production of ethanol fuel is about 20 to 21 billion litres annually.

In the US, fuel ethanol production has grown steadily from an insignificant amount in 1978 to more than 6 billion litres in 2000 (Kintisch, 2001). This tremendous growth in fuel ethanol output is due to a variety of reasons. However, all have something in common, namely a strong dependence on government intervention. Ethanol was and is promoted as a solution for a variety of complex problems, among them:

• US dependence on foreign oil supplies, which became very apparent in the two oil crises of the 1970s;

• low gasoline-octane ratings caused by reduced use of lead after the approval of the Clean Air Act in 1977;

• low farm incomes caused by the grain surplus in the wake of the Soviet embargo; and

• air pollution.

The real boost for ethanol production in the US came in the 1990s, when energy policy was shifting as oil prices stopped rising (and the supply situation seemed to have stabilized). Energy self-sufficiency ceased to be a top priority and environmental issues started to increase in importance. Compared to fossil fuels, bioethanol was seen as having the advantages of being renewable, cleaner burning and producing no net greenhouse gases. In 1990, President Bush signed into law the Clean Air Act Amendments. Among its provisions is a requirement that certain regions should use oxygenated, reformulated gasoline during certain high-smog periods. Moreover, the law required that a certain percentage of oxygenates should be derived from renewable sources. Because it was renewable, ethanol became the favorable oxygenate for many consumers.

Despite claims of widespread net benefits from the US ethanol program (which is essentially a corn-based program), most analysts believe US production is crucially dependent on government support. This support is provided mainly in the form of federal and state tax concessions (Berg, 2000). However, supporters of the current system argue that the net benefit of bioethanol in the fuel far outweighs the outlay. They cite in particular the following impacts of ethanol production (Evans, 1997; Berg, 2000):

• increase in net farm income by US$4.5 billion;

• increase in employment by 195,200 jobs;

• increase in state tax receipts by over US$450 million;

• improvement of the US trade deficit by US$2 billion;

• net saving to the federal budget of US$3.6 billion.

Despite these impressive claims, the stand-alone economic viability of fuel ethanol production remains somewhat suspect. The 1999 California Energy Commission’s report on the potential of state-sponsored biomass-to-fuel ethanol programs (CEC, 1999) provides an overview of a number of the issues and the costs and benefits. The report concludes that converting biomass wastes and residues into ethanol has the potential to meet the state's oxygenated gasoline needs as well as offering a number of potential energy, environmental and economic benefits. However, it also finds that the cost of producing ethanol is high. As a result, the development of a Californian ethanol industry would require a state government role (investment) in overcoming economic, technical, and institutional barriers and uncertainties. In addition to this developmental role for the state, the report also concludes that as Californian-produced ethanol fuel is likely to face stiff competition from out-of-state ethanol supplies and in-state petroleum products, continued government price support would be required to make it a competitive fuel additive.

Other reports that have focused more directly on wood as a feedstock have also produced similar conclusions, while at the same time highlighting questions as to commercial status of the technologies. A New Zealand study (Anon, 1979) produced an estimated cost of wood ethanol that in current dollar terms would be around US56c/litre (or US$26/GJ). More recently, there have been calls for the British Columbian government (Canada) to enter into negotiations to establish a demonstration wood ethanol plant. This following on from an industry recommendation (requested by the BC Minister of Environment, Lands and Parks) of actions to be taken to keep greenhouse gas emissions within the bounds agreed by Canada as part of the Kyoto Protocol. McCloy & O’Conner (1998) reviewed five possible technologies for producing ethanol from wood, including their status and economic viability. That review concluded that while there were strong environmental, health and (possibly) economic reasons for BC to increase the use of ethanol as a transportation fuel, none of the reviewed technologies could be considered as being currently commercially proven.

In summarizing their findings, McCloy and O’Conner state that:

It is difficult to compare the leading technologies [since they are] at different stages of development [and] the level of certainty surrounding each process is different.

Table 4 compares the five technologies reviewed in the report with the established grain-to-ethanol technology. The costs for the grain plant do not include interest, taxes, depreciation or profit, as these are project-dependent.

Table 4: Comparison of Process Economics

Grain

Iogen

BC International

Arkenol

ACOS

Bioengineer

Resources

Development

Status

Proven & commercial

Building Demonstration

Building Commercial

Laboratory

Laboratory

Laboratory/Pilot/Demo

Capital cost

$0.5/l

Higher

Higher

Much Higher

Higher

Similar

Feedstock

Grain

Agricultural residues

Bagasse

Softwood

Softwood

Softwood and Bark

Feedstock cost

$0.3/l

Lower

Lower

Lower

Lower

Much lower

Co-product value

$0.15/l

Lower

Lower

Lower

Higher?

Lower?

Operating Costs

Energy

$0.05/l

Higher

Higher

Higher

Same?

Same?

Labor

$0.045/l

Higher

Higher

Higher

Higher

Same?

Chemicals

$0.03/l

Higher

Higher

Higher

Higher

Lower?

Maintenance

$0.025/l

Higher

Higher

Higher

Higher

Higher?

Overhead

$0.04/l

Higher

Higher

Higher

Higher

Same?

Total

$0.34/l

Higher Today

Higher Today

Higher Today

Lower?

Lower?

Source: McCloy & O’Conner (1998)

McCloy & O’Conner (ibid. p 98) then go on to state that:

It can be seen that none of the technologies reviewed are at the same development stage as the proven grain to ethanol technology. The new technologies cannot be considered to be commercial today. All of the technologies have substantial room for further development that has the potential to make them competitive in the future.

The data in Table 4, once the capital cost of the plant is included, would imply that the cost of grain-based ethanol is of the order of US$0.55/litre. The data also suggest that the indexed cost of wood-based ethanol from the 1979 New Zealand study may not be that different.

The use of by-products in ethanol fuel production is very important from a resource, environmental, financial, economic and social point of view, as well as a means of reducing production costs. For example, a bushel (0.03524 m3) of corn used for producing ethanol fuel produces 1.6 pounds (0.73 kg) of corn oil, 10.9 pounds (4.94 kg) of high protein feed (distillers dried grain or DDG), 2.6 pounds (1.40 kg) of corn meal, and 31.5 pounds (14.27kg) of starch, according the Corn Grower Association. (CFDC, 2001).

With most North American corn based ethanol technologies aiming for a selling price (including tax incentives) of some 45 cents per liter (McCloy and O’Conner 1998), a production cost of 55 cents/liter for corn-based ethanol is viable for the producer. However, if sugarcane was used instead, with much higher productivity and far lower inputs, the overall energy balance will be positive and the costs far lower. This is because favorable federal tax provisions effectively reduce the retail price of ethanol by 54 cents per gallon, or US$0.1426/litre (CEC, 1999). Berg (2000) as well as listing the federal blender’s tax credit lists a number of exemptions applying to US fuel ethanol production. As a result, government support to the fuel ethanol industry would appear to be greater than that given in the CEC report. The exemptions listed by Berg (2000) are:

This list implies support for fuel ethanol in excess of US18 cents per liter. On these figures a selling price of around US45c/litre would be consistent with production costs of more than US63 cents per liter, or a fuel cost of more than US$29/GJ10.

North American demand for fuel ethanol is expected to continue to grow despite some doubts as to whether blending ethanol into petrol is the most cost effective way of making a clean-burning fuel (Kintisch, 2001). Reasons for the continued growth in the use of ethanol, despite its cost relative to petroleum products include not only its ability to supply the mandated “oxygenates” requirements in fuel, but also widespread political support (Kintisch, 2001; Berg, 2000), the fact that it is seen to be a “green” or environmentally friendly product, and growing concerns with the environmental and health impacts of MTBE (methyl tertiary-butyl ether) (Berg, 2000, CEC, 1999). This is the fuel additive that was once supposed to be the answer to air pollution (Kintisch, 2001) and the most cost effective (least cost) way of oxygenating and enhancing the octane rating of petroleum fuels.

For Europe, and in particular the EU countries, the economics of bioethanol would not appear to be any better than in any other part of the world (NOVEM, 1992). However, Europe is one area where there is considerable interest in biofuels and where in fact there are biofuels that are readily commercially available in some countries. These are most notably bio-diesel – typically methyl rapeseed oil esters – the production of which is heavily subsidized and which are commercially available in Austria, France and Germany (Sims, 1996).

9 A recent report summarizing the current role of biomass in the energy-economies of 12 European countries ‘Strategies for the Development of Biomass as an Energy-Carrier in Europe’ (www.ecop.ucl.ac.be/aebiom/publications/PAPER4.HTM) gives the figure.

10 These subsidies should be considered in the light of hidden subsidies given to fossil fuels. For example a recent report of the USA General Accounting Office (GAO, 2000), shows that the petroleum industry has received over US$150 billion in tax breaks in the past 32 years alone. Foreign investment tax credits are estimated to cost the Treasury a further US$7 billion/yr. This compares with about $11 billion paid to the ethanol industry since 1979.